We could not find any results for:
Make sure your spelling is correct or try broadening your search.
Share Name | Share Symbol | Market | Type |
---|---|---|---|
Viper Energy Inc | NASDAQ:VNOM | NASDAQ | Common Stock |
Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|---|---|
0.47 | 1.27% | 37.62 | 10.28 | 39.98 | 37.83 | 36.975 | 37.37 | 840,551 | 05:00:08 |
|
|
|
|
|
|
|
|
|
|
|
|
ý
|
ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
o
|
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
|
|
|
Delaware
|
|
46-5001985
|
(State or Other Jurisdiction of
Incorporation or Organization)
|
|
(IRS Employer
Identification Number)
|
|
|
|
500 West Texas, Suite 1200
Midland, Texas
|
|
79701
|
(Address of Principal Executive Offices)
|
|
(Zip Code)
|
|
|
Securities registered pursuant to Section 12(b) of the Act:
|
|
|
||
|
Title of Each Class
|
|
|
|
Name of Each Exchange on Which Registered
|
|
|
Common Units Representing Limited Partner Interests
|
|
|
|
The NASDAQ Stock Market LLC
|
|
|
|
Securities registered pursuant to Section 12(g) of the Act: None
|
(Global Market)
|
|
Large Accelerated Filer
|
|
o
|
|
Accelerated Filer
|
|
ý
|
|
|
|
|
|||
Non-Accelerated Filer
|
|
o
|
|
Smaller Reporting Company
|
|
o
|
|
|
|
|
|
|
|
|
|
|
|
Page
|
|
|
PART I
|
|
|
|
PART II
|
|
|
|
PART III
|
|
|
|
PART IV
|
|
Index to Combined Consolidated Financial Statements
|
|
3-D seismic
|
Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
|
Basin
|
A large depression on the earth’s surface in which sediments accumulate.
|
Bbl
|
Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
|
Bbls/d
|
Barrels per day.
|
BOE
|
Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
|
BOE/d
|
Barrels of oil equivalent per day.
|
British Thermal Unit or Btu
|
The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
|
Completion
|
The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
|
Condensate
|
Liquid hydrocarbons associated with the production that is primarily natural gas.
|
Crude oil
|
Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
|
Deterministic method
|
The method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation is used in the reserves estimation procedure.
|
Developed acreage
|
Acreage allocated or assignable to productive wells.
|
Development costs
|
Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves.
|
Development well
|
A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
|
Differential
|
An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
|
Dry hole or dry well
|
A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
|
Estimated Ultimate Recovery or EUR
|
Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
|
Exploitation
|
A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
|
Exploratory well
|
A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
|
Field
|
An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
|
Finding and development costs
|
Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
|
Fracturing
|
The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.
|
Gross acres or gross wells
|
The total acres or wells, as the case may be, in which a working interest is owned.
|
Horizontal drilling
|
A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.
|
Horizontal wells
|
Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
|
MBbls
|
Thousand barrels of crude oil or other liquid hydrocarbons.
|
MBOE
|
One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
|
Mcf
|
Thousand cubic feet of natural gas.
|
Mineral interests
|
The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
|
MMBtu
|
Million British Thermal Units.
|
MMcf
|
Million cubic feet of natural gas.
|
Net acres
|
The sum of the fractional working interest owned in gross acres.
|
Oil and natural gas properties
|
Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
|
Operator
|
The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
|
Play
|
A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.
|
Plugging and abandonment
|
Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
|
PUD
|
Proved undeveloped.
|
Productive well
|
A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
|
Prospect
|
A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
|
Proved developed reserves
|
Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
|
Proved reserves
|
The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
|
Proved undeveloped reserves
|
Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
|
Recompletion
|
The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
|
Reserves
|
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
|
Reservoir
|
A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
|
Resource play
|
A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.
|
Royalty interest
|
An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development or operations.
|
Spacing
|
The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
|
Standardized measure
|
The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.
|
Tight formation
|
A formation with low permeability that produces natural gas with very low flow rates for long periods of time.
|
Undeveloped acreage
|
Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
|
Wellbore
|
The hole drilled by the bit that is equipped for oil or natural gas production on a completed well.
|
Working interest
|
An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
|
WTI
|
West Texas Intermediate.
|
Delaware Act
|
Delaware Revised Uniform Limited Partnership Act.
|
Diamondback
|
Diamondback Energy, Inc., a Delaware corporation.
|
EPA
|
U.S. Environmental Protection Agency.
|
Exchange Act
|
The Securities Exchange Act of 1934, as amended.
|
FERC
|
Federal Energy Regulatory Commission.
|
GAAP
|
Accounting principles generally accepted in the United States.
|
General partner
|
Viper Energy Partners GP LLC, a Delaware limited liability company; the general partner of the Partnership and a wholly-owned subsidiary of Diamondback.
|
Inception
|
September 18, 2013, the date Viper Energy Partners LLC was formed.
|
IPO
|
The partnership’s initial public offering of common units.
|
IRS
|
Internal Revenue Service.
|
LTIP
|
Viper Energy Partners LP Long Term Incentive Plan.
|
OSHA
|
Federal Occupational Safety and Health Act.
|
Partnership
|
Viper Energy Partners LP, a Delaware limited partnership.
|
Partnership agreement
|
The first amended and restated agreement of limited partnership, dated as of June 23, 2014, entered into by the general partner and Diamondback in connection with the closing of the IPO.
|
Predecessor
|
Viper Energy Partners LLC, a Delaware limited liability company, and a wholly-owned subsidiary of the Partnership.
|
Ryder Scott
|
Ryder Scott Company, L.P.
|
SEC
|
Securities and Exchange Commission.
|
Securities Act
|
The Securities Act of 1933, as amended.
|
Wells Fargo
|
Wells Fargo Bank, National Association.
|
•
|
our ability to execute our business strategies;
|
•
|
the volatility of realized oil and natural gas prices;
|
•
|
the level of production on our properties;
|
•
|
regional supply and demand factors, delays or interruptions of production;
|
•
|
our ability to replace our oil and natural gas reserves;
|
•
|
our ability to identify, complete and integrate acquisitions of properties or businesses;
|
•
|
general economic, business or industry conditions;
|
•
|
competition in the oil and natural gas industry;
|
•
|
the ability of our operators to obtain capital or financing needed for development and exploration operations;
|
•
|
title defects in the properties in which we invest;
|
•
|
uncertainties with respect to identified drilling locations and estimates of reserves;
|
•
|
the availability or cost of rigs, equipment, raw materials, supplies, oilfield services or personnel;
|
•
|
restrictions on the use of water;
|
•
|
the availability of transportation facilities;
|
•
|
the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
|
•
|
federal and state legislative and regulatory initiatives relating to hydraulic fracturing;
|
•
|
future operating results;
|
•
|
exploration and development drilling prospects, inventories, projects and programs;
|
•
|
operating hazards faced by our operators; and
|
•
|
the ability of our operators to keep pace with technological advancements.
|
•
|
Capitalize on the development of the properties underlying our mineral interests
. Our assets consist primarily of mineral interests in the Permian Basin in West Texas. We expect the production from our mineral interests to increase as Diamondback and our other operators drill and develop our acreage without cost to us.
|
•
|
Leverage our relationship with Diamondback to participate with it in acquisitions of mineral or other interests in producing properties from third parties and to increase the size and scope of our potential third-party acquisition targets
. We intend to make opportunistic acquisitions of mineral interests that have substantial oil-weighted resource potential and organic growth potential. Diamondback was formed in part to acquire and develop oil and natural gas properties, some of which will likely meet our acquisition criteria. In addition, Diamondback’s executives have long histories of evaluating, pursuing and consummating oil and natural gas property acquisitions in North America. Through our relationships with Diamondback and its affiliates, we have access to their significant pool of management talent and industry relationships, which we believe provide us with a competitive advantage in pursuing potential third-party acquisition opportunities. We may have additional opportunities to work jointly with Diamondback to pursue certain acquisitions of mineral or other interests in oil and natural gas properties from third parties. For example, we and Diamondback may jointly pursue an acquisition where we would acquire mineral or other interests in properties and Diamondback would acquire the remaining working and revenue interests in such properties. We believe this arrangement may give us access to third-party acquisition opportunities that we would not otherwise be in a position to pursue.
|
•
|
Seek to acquire from Diamondback, from time to time, mineral or other interests in producing oil and natural gas properties that meet our acquisition criteria
. Since our formation, we have acquired, and may have additional opportunities from time to time in the future to acquire, mineral or other interests in producing oil and natural gas properties directly from Diamondback. We believe Diamondback may be incentivized to sell properties to us, as doing so may enhance Diamondback’s economic returns by monetizing long-lived producing properties while potentially retaining a portion of the resulting cash flow through distributions on Diamondback’s limited partner interests in us. However, none of Diamondback or any of its affiliates is contractually obligated to offer or sell any interests in properties to us.
|
•
|
Oil rich resource base in one of North America’s leading resource plays
. All of the acreage underlying our mineral interests is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. The majority of our current properties are well positioned in the core of both the Midland and Delaware Basins. Production on our properties for the
year ended December 31, 2016
was approximately
76%
oil,
14%
natural gas liquids and
10%
natural gas. As of
December 31, 2016
, our estimated net proved reserves were comprised of approximately
68%
oil,
18%
natural gas liquids and
14%
natural gas.
|
•
|
Multi-year drilling inventory in one of North America’s leading oil resource plays.
Diamondback, as the operator of approximately
41%
of our acreage, has advised us that it has identified a multi-year inventory of potential drilling locations for our oil-weighted reserves from the acreage underlying our mineral interests. At an assumed price of
$50.00
per Bbl WTI, Diamondback had identified approximately
273
potential economic horizontal locations on the acreage Diamondback operates in its Spanish Trail area in Midland County, Texas, based on Diamondback’s evaluation of applicable geologic and engineering data. These locations have an average lateral length of approximately 8,300 feet, with the actual length depending on lease geometry and other considerations, and exist across most of the acreage and in multiple horizons. Of these potential economic locations,
106
are in the Wolfcamp B and Lower Spraberry horizons, with the remaining horizontal locations in the Wolfcamp A, Middle Spraberry, Clearfork and Cline horizons. Diamondback’s current potential horizontal location count is based on
660
-foot spacing between wells in the Wolfcamp B horizon,
500
-foot spacing in the Lower Spraberry horizon,
880
-foot spacing in the Wolfcamp A and Middle Spraberry horizons, and
1,320
-foot spacing in the Clearfork and Cline horizons. The ultimate inter-well spacing may vary from these distances due to different factors, which would result in a higher or lower location count. Based on horizontal wells drilled to date, Ryder Scott assigned gross reserves to PUD locations ranging from
620
MBOE for 7,500-foot laterals in the Wolfcamp B to
1,273
MBOE for 10,000-foot laterals in the Lower Spraberry. When normalized to 7,500-foot laterals, Ryder Scott assigned average PUD values of
609
MBOE for the Wolfcamp B horizon,
983
MBOE for the Lower Spraberry horizon, 630 MBOE for the Middle Spraberry and
789
MBOE for the Wolfcamp A horizon. These PUD locations, as assigned by Ryder Scott, are for direct offsets to producing wells. Based on various geologic and engineering parameters, we believe that the estimates assigned to these PUD locations are reasonable estimates for development locations on the remaining portion of our acreage. Additionally, we believe that there is similar potential for horizontal development on the portion of our acreage for which Diamondback is not the operator.
|
•
|
review and verification of historical production data, which data is based on actual production as reported by our operators;
|
•
|
preparation of reserve estimates by the Vice President–Reservoir Engineering of our general partner or under his direct supervision;
|
•
|
review by the Vice President–Reservoir Engineering of our general partner of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;
|
•
|
direct reporting responsibilities by the Vice President–Reservoir Engineering of our general partner to the Chief Executive Officer of our general partner;
|
•
|
verification of property ownership by our land department; and
|
•
|
no employee’s compensation is tied to the amount of reserves booked.
|
|
December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Estimated proved developed reserves:
|
|
|
|
|
|
|||
Oil (Bbls)
|
12,332,000
|
|
|
9,700,000
|
|
|
6,951,892
|
|
Natural gas (Mcf)
|
15,933,000
|
|
|
13,739,050
|
|
|
10,377,401
|
|
Natural gas liquids (Bbls)
|
3,247,000
|
|
|
2,204,951
|
|
|
1,470,966
|
|
Total (BOE)
|
18,235,000
|
|
|
14,194,793
|
|
|
10,152,425
|
|
Estimated proved undeveloped reserves:
|
|
|
|
|
|
|||
Oil (Bbls)
|
9,012,000
|
|
|
8,677,422
|
|
|
5,878,402
|
|
Natural gas (Mcf)
|
11,158,000
|
|
|
10,568,835
|
|
|
8,616,759
|
|
Natural gas liquids (Bbls)
|
2,329,000
|
|
|
1,711,005
|
|
|
1,042,742
|
|
Total (BOE)
|
13,200,000
|
|
|
12,149,900
|
|
|
8,357,271
|
|
Estimated Net Proved Reserves:
|
|
|
|
|
|
|||
Oil (Bbls)
|
21,344,000
|
|
|
18,377,422
|
|
|
12,830,294
|
|
Natural gas (Mcf)
|
27,091,000
|
|
|
24,307,885
|
|
|
18,994,160
|
|
Natural gas liquids (Bbls)
|
5,576,000
|
|
|
3,915,956
|
|
|
2,513,708
|
|
Total (BOE)(1)
|
31,435,000
|
|
|
26,344,693
|
|
|
18,509,696
|
|
Percent proved developed
|
58.0
|
%
|
|
53.9
|
%
|
|
54.8
|
%
|
(1)
|
Estimates of reserves as of
December 31, 2016
,
2015
and
2014
were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended
December 31, 2016
,
2015
and
2014
, respectively, in accordance with SEC guidelines applicable to reserve estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
|
•
|
additions of
4,520
MBOE, primarily from
32
horizontal well locations,
16
in the Wolfcamp interval and
16
in Spraberry and Bone Spring intervals, attributable to extensions resulting from strategic drilling of wells to delineate our acreage position;
|
•
|
downgrade of PUDs into probable category of
206
MBOE for
two
short lateral horizontal wells that are not expected to be drilled due to the lower price environment;
|
•
|
the conversion of approximately
2,962
MBOE attributable to PUDs into proved developed reserves; and
|
•
|
negative revisions of approximately
302
MBOE in PUDs primarily due to lower product pricing.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Production Data:
|
|
|
|
|
|
||||||
Oil (Bbls)
|
1,777,922
|
|
|
1,555,493
|
|
|
856,541
|
|
|||
Natural gas (Mcf)
|
1,490,382
|
|
|
1,128,605
|
|
|
648,808
|
|
|||
Natural gas liquids (Bbl)
|
327,899
|
|
|
238,716
|
|
|
144,074
|
|
|||
Combined volumes (BOE)
|
2,354,218
|
|
|
1,982,310
|
|
|
1,108,750
|
|
|||
Daily combined volumes (BOE/d)
|
6,432
|
|
|
5,431
|
|
|
3,038
|
|
|||
Average Prices:
|
|
|
|
|
|
||||||
Oil (per Bbl)
|
$
|
40.23
|
|
|
$
|
44.75
|
|
|
$
|
82.98
|
|
Natural gas (per Mcf)
|
2.08
|
|
|
2.36
|
|
|
4.18
|
|
|||
Natural gas liquids (per Bbl)
|
12.84
|
|
|
10.85
|
|
|
27.59
|
|
|||
Combined (per BOE)
|
33.49
|
|
|
37.76
|
|
|
70.14
|
|
Basin
|
Gross Acreage
|
|
Net Acreage
|
||
Permian
|
107,568
|
|
|
30,442
|
|
•
|
the location of wells;
|
•
|
the method of drilling and casing wells;
|
•
|
the timing of construction or drilling activities, including seasonal wildlife closures;
|
•
|
the rates of production or “allowables”;
|
•
|
the surface use and restoration of properties upon which wells are drilled;
|
•
|
the plugging and abandoning of wells; and
|
•
|
notice to, and consultation with, surface owners and other third parties.
|
•
|
the domestic and foreign supply of oil and natural gas;
|
•
|
the level of prices and expectations about future prices of oil and natural gas;
|
•
|
the level of global oil and natural gas exploration and production;
|
•
|
the cost of exploring for, developing, producing and delivering oil and natural gas;
|
•
|
the price and quantity of foreign imports;
|
•
|
political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;
|
•
|
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
|
•
|
speculative trading in crude oil and natural gas derivative contracts;
|
•
|
the level of consumer product demand;
|
•
|
weather conditions and other natural disasters;
|
•
|
risks associated with operating drilling rigs;
|
•
|
technological advances affecting energy consumption;
|
•
|
the price and availability of alternative fuels;
|
•
|
domestic and foreign governmental regulations and taxes;
|
•
|
the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;
|
•
|
the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and
|
•
|
overall domestic and global economic conditions.
|
•
|
commodity prices;
|
•
|
the timing and amount of capital expenditures by our operators, which could be significantly more than anticipated;
|
•
|
the ability of our operators to access capital;
|
•
|
the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
|
•
|
the operators’ expertise, operating efficiency and financial resources;
|
•
|
approval of other participants in drilling wells;
|
•
|
the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;
|
•
|
the selection of technology;
|
•
|
the selection of counterparties for the sale of production; and
|
•
|
the rate of production of the reserves.
|
•
|
recoverable reserves;
|
•
|
future oil and natural gas prices and their applicable differentials;
|
•
|
operating costs; and
|
•
|
potential environmental and other liabilities.
|
•
|
unusual or unexpected geological formations;
|
•
|
loss of drilling fluid circulation;
|
•
|
title problems;
|
•
|
facility or equipment malfunctions;
|
•
|
unexpected operational events;
|
•
|
shortages or delivery delays of equipment and services;
|
•
|
compliance with environmental and other governmental requirements; and
|
•
|
adverse weather conditions.
|
•
|
Our general partner is allowed to take into account the interests of parties other than us, such as Diamondback, in exercising certain rights under our partnership agreement.
|
•
|
Neither our partnership agreement nor any other agreement requires Diamondback to pursue a business strategy that favors us.
|
•
|
Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.
|
•
|
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
|
•
|
Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders.
|
•
|
Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.
|
•
|
Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf.
|
•
|
Our general partner intends to limit its liability regarding our contractual and other obligations.
|
•
|
Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.
|
•
|
Our general partner controls the enforcement of obligations that it and its affiliates owe to us.
|
•
|
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
|
•
|
how to allocate business opportunities among us and its affiliates;
|
•
|
whether to exercise its call right;
|
•
|
how to exercise its voting rights with respect to the units it owns;
|
•
|
whether to exercise its registration rights; and
|
•
|
whether or not to consent to any merger or consolidation of the partnership or any amendment to the partnership agreement.
|
•
|
whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
|
•
|
our general partner and its executive officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its executive officers or directors engaged in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and
|
•
|
our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction, even a transaction with an affiliate or the resolution of a conflict of interest, is:
|
•
|
approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or
|
•
|
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.
|
•
|
the proportionate ownership interest of unitholders in us immediately prior to the issuance will decrease;
|
•
|
the amount of cash distributions on each common unit may decrease;
|
•
|
the ratio of our taxable income to distributions may increase;
|
•
|
the relative voting strength of each previously outstanding common unit may be diminished; and
|
•
|
the market price of the common units may decline.
|
Period:
|
High
|
|
Low
|
|
Cash Distributions per Common Unit
(1)
|
||||||
2016
|
|
|
|
|
|
||||||
1st Quarter
|
$
|
17.50
|
|
|
$
|
12.69
|
|
|
$
|
0.149
|
|
2nd Quarter
|
$
|
20.25
|
|
|
$
|
16.07
|
|
|
$
|
0.189
|
|
3rd Quarter
|
$
|
19.60
|
|
|
$
|
15.10
|
|
|
$
|
0.207
|
|
4th Quarter
|
$
|
17.41
|
|
|
$
|
13.53
|
|
|
$
|
0.258
|
|
2015
|
|
|
|
|
|
||||||
1st Quarter
|
$
|
19.87
|
|
|
$
|
16.25
|
|
|
$
|
0.190
|
|
2nd Quarter
|
$
|
22.10
|
|
|
$
|
17.44
|
|
|
$
|
0.220
|
|
3rd Quarter
|
$
|
21.50
|
|
|
$
|
13.40
|
|
|
$
|
0.200
|
|
4th Quarter
|
$
|
17.45
|
|
|
$
|
13.31
|
|
|
$
|
0.228
|
|
(1)
|
Distributions are shown for the quarter in which they were generated.
|
|
Year Ended December 31,
|
|
Period From Inception
Through December 31, 2013 |
||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
|||||||||
|
(in thousands)
|
||||||||||||||
Statement of Operations Data:
|
|
|
|
|
|
|
|
||||||||
Royalty income
|
$
|
78,837
|
|
|
$
|
74,859
|
|
|
$
|
77,767
|
|
|
$
|
14,987
|
|
Lease bonus
|
309
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Total operating income
|
79,146
|
|
|
74,859
|
|
|
77,767
|
|
|
14,987
|
|
||||
Costs and expenses:
|
|
|
|
|
|
|
|
||||||||
Production and ad valorem taxes
|
5,544
|
|
|
5,531
|
|
|
5,377
|
|
|
972
|
|
||||
Gathering and transportation
|
415
|
|
|
259
|
|
|
—
|
|
|
—
|
|
||||
Depletion
|
29,820
|
|
|
35,436
|
|
|
27,601
|
|
|
5,199
|
|
||||
Impairment
|
47,469
|
|
|
3,423
|
|
|
—
|
|
|
—
|
|
||||
General and administrative expenses
|
5,209
|
|
|
5,835
|
|
|
4,372
|
|
|
87
|
|
||||
Total costs and expenses
|
88,457
|
|
|
50,484
|
|
|
37,350
|
|
|
6,258
|
|
||||
Income (loss) from operations
|
(9,311
|
)
|
|
24,375
|
|
|
40,417
|
|
|
8,729
|
|
||||
Other income (expense):
|
|
|
|
|
|
|
|
||||||||
Interest expense
|
(2,455
|
)
|
|
(1,110
|
)
|
|
(487
|
)
|
|
—
|
|
||||
Interest expense—related party, net of capitalized interest
|
—
|
|
|
—
|
|
|
(10,755
|
)
|
|
(5,741
|
)
|
||||
Other income
|
867
|
|
|
1,154
|
|
|
459
|
|
|
—
|
|
||||
Total other income (expense), net
|
(1,588
|
)
|
|
44
|
|
|
(10,783
|
)
|
|
(5,741
|
)
|
||||
Net income (loss)
|
$
|
(10,899
|
)
|
|
$
|
24,419
|
|
|
$
|
29,634
|
|
|
$
|
2,988
|
|
|
|
|
|
|
|
|
|
||||||||
Allocation of net income:
|
|
|
|
|
|
|
|
||||||||
Net income attributable to the period January 1, 2014 through June 22, 2014
|
|
|
|
|
$
|
7,021
|
|
|
|
||||||
Net income attributable to the period June 23, 2014 through December 31, 2014
|
|
|
|
|
22,613
|
|
|
|
|||||||
|
|
|
|
|
$
|
29,634
|
|
|
|
||||||
|
|
|
|
|
|
|
|
||||||||
Net income attributable to common limited partners per unit:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(0.13
|
)
|
|
$
|
0.31
|
|
|
$
|
0.29
|
|
|
|
||
Diluted
|
$
|
(0.13
|
)
|
|
$
|
0.31
|
|
|
$
|
0.29
|
|
|
|
||
|
|
|
|
|
|
|
|
||||||||
Statement of Cash Flow Data:
|
|
|
|
|
|
|
|
||||||||
Net cash provided by (used in):
|
|
|
|
|
|
|
|
||||||||
Operating activities
|
$
|
68,627
|
|
|
$
|
63,832
|
|
|
$
|
51,813
|
|
|
$
|
4,845
|
|
|
Year Ended December 31,
|
|
Period From Inception
Through December 31, 2013 |
||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
|||||||||
|
(in thousands)
|
||||||||||||||
Investing activities
|
(205,721
|
)
|
|
(43,907
|
)
|
|
(96,815
|
)
|
|
(4,083
|
)
|
||||
Financing activities
|
145,768
|
|
|
(34,496
|
)
|
|
59,350
|
|
|
—
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Other Financial Data:
|
|
|
|
|
|
|
|
||||||||
Adjusted EBITDA
(1)
|
$
|
72,660
|
|
|
$
|
68,317
|
|
|
$
|
70,579
|
|
|
$
|
13,928
|
|
|
|
|
|
|
|
|
|
||||||||
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
9,213
|
|
|
$
|
539
|
|
|
$
|
15,110
|
|
|
|
||
Total assets
|
670,549
|
|
|
529,731
|
|
|
537,402
|
|
|
|
|||||
Total liabilities
|
122,651
|
|
|
34,587
|
|
|
2,051
|
|
|
|
|||||
Unitholders’ equity/Members’ equity
|
547,898
|
|
|
495,144
|
|
|
535,351
|
|
|
|
(1)
|
For more information, please read “—Non-GAAP Financial Measure” below.
|
|
Year Ended December 31,
|
|
Period From Inception
Through
December 31, 2013
|
||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
|||||||||
|
(in thousands)
|
||||||||||||||
Net income (loss)
|
$
|
(10,899
|
)
|
|
$
|
24,419
|
|
|
$
|
29,634
|
|
|
$
|
2,988
|
|
Interest expense
|
2,455
|
|
|
1,110
|
|
|
487
|
|
|
—
|
|
||||
Interest expense–related party, net of capitalized interest
|
—
|
|
|
—
|
|
|
10,755
|
|
|
5,741
|
|
||||
Non-cash unit-based compensation expense
|
3,815
|
|
|
3,929
|
|
|
2,102
|
|
|
—
|
|
||||
Depletion
|
29,820
|
|
|
35,436
|
|
|
27,601
|
|
|
5,199
|
|
||||
Impairment
|
47,469
|
|
|
3,423
|
|
|
—
|
|
|
—
|
|
||||
Adjusted EBITDA
|
$
|
72,660
|
|
|
$
|
68,317
|
|
|
$
|
70,579
|
|
|
$
|
13,928
|
|
ITEM 7.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
|
Year Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Royalty income
|
|
|
|
|
|
|||
Oil sales
|
91
|
%
|
|
93
|
%
|
|
91
|
%
|
Natural gas sales
|
4
|
%
|
|
4
|
%
|
|
3
|
%
|
Natural gas liquid sales
|
5
|
%
|
|
3
|
%
|
|
6
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
•
|
In connection with the closing of the IPO, the subordinated note issued by our predecessor to Diamondback effective September 19, 2013 was converted to equity; therefore, we no longer have the note payable and related interest expense.
|
•
|
On July 8, 2014, we entered into a secured revolving credit agreement with Wells Fargo as the administrative agent, sole book runner and lead arranger. The credit agreement, as amended, provides for a revolving credit facility in the maximum amount of
$500.0 million
, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined semi-annually with effective dates of April 1st and October 1st. In addition, we may request up to
three
additional redeterminations of the borrowing base during any
12
-month period. As of
December 31, 2016
, the borrowing base was set at
$275.0 million
and we had
$120.5 million
in outstanding borrowings. Upon completion of our January 2017 underwritten public offering of common units, we repaid all of the outstanding borrowings under our revolving credit agreement, and as of February 13, 2017, had no borrowings outstanding under this facility.
|
•
|
We incur incremental general and administrative expenses of approximately $2.5 million annually as a result of being a publicly traded limited partnership, consisting of expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, NASDAQ Global Select Market listing, independent auditor fees, legal fees, investor relations activities, registrar and transfer agent fees, director and officer insurance and director compensation.
|
•
|
The partnership agreement requires us to reimburse our general partner for all direct and indirect expenses incurred or paid on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. The partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us. For the year ended
December 31, 2016
, the General Partner did
no
t receive any reimbursements from the Partnership. For the year ended
December 31, 2015
, the General Partner did not receive any reimbursements from the Partnership other than the
$4,000
outstanding at December 31, 2014.
|
•
|
On June 17, 2014, under our Long Term Incentive Plan, or the LTIP, adopted in connection with the IPO, we granted awards of an aggregate of 2,500,000 unit options under the LTIP to executive officers of our general partner. For the years ended
December 31, 2016
and
2015
, we incurred
$3.8 million
and
$3.9 million
, respectively, of unit–based compensation.
|
•
|
In connection with the closing of the IPO, we and our general partner entered into an advisory services agreement with Wexford pursuant to which Wexford provides general financial and strategic advisory services to us and our general partner in exchange for a
$0.5 million
annual fee and certain expense reimbursement. For the year ended
December 31, 2016
, we did
no
t incur any costs under the advisory services agreement. For the year ended
December 31, 2015
, we incurred costs of
$0.5 million
under the advisory services agreement.
|
•
|
In connection with the closing of the IPO, we entered into a tax sharing agreement with Diamondback pursuant to which we are required to reimburse Diamondback for our share of state and local income and other taxes for which our results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax we would have paid had we not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe less or no tax. In such a situation, we would reimburse Diamondback for the tax we would have owed had the tax attributes not been available or used for our benefit, even though Diamondback had no cash tax expense for that period. During the year ended
December 31, 2016
, we did not reimburse Diamondback under the tax sharing agreement.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(In thousands)
|
||||||||||
Operating Results:
|
|
|
|
|
|
||||||
Royalty income
|
$
|
78,837
|
|
|
$
|
74,859
|
|
|
$
|
77,767
|
|
Lease bonus
|
309
|
|
|
—
|
|
|
—
|
|
|||
Total operating income
|
79,146
|
|
|
74,859
|
|
|
77,767
|
|
|||
Costs and expenses:
|
|
|
|
|
|
||||||
Production and ad valorem taxes
|
5,544
|
|
|
5,531
|
|
|
5,377
|
|
|||
Gathering and transportation
|
415
|
|
|
259
|
|
|
—
|
|
|||
Depletion
|
29,820
|
|
|
35,436
|
|
|
27,601
|
|
|||
Impairment
|
47,469
|
|
|
3,423
|
|
|
—
|
|
|||
General and administrative expenses
|
5,209
|
|
|
5,835
|
|
|
4,372
|
|
|||
Total costs and expenses
|
88,457
|
|
|
50,484
|
|
|
37,350
|
|
|||
Income (loss) from operations
|
(9,311
|
)
|
|
24,375
|
|
|
40,417
|
|
|||
Other income (expense):
|
|
|
|
|
|
||||||
Interest expense
|
(2,455
|
)
|
|
(1,110
|
)
|
|
(487
|
)
|
|||
Interest expense—related party, net of capitalized interest
|
—
|
|
|
—
|
|
|
(10,755
|
)
|
|||
Other income
|
867
|
|
|
1,154
|
|
|
459
|
|
|||
Total other income (expense), net
|
(1,588
|
)
|
|
44
|
|
|
(10,783
|
)
|
|||
Net income (loss)
|
$
|
(10,899
|
)
|
|
$
|
24,419
|
|
|
$
|
29,634
|
|
Allocation of net income:
|
|
|
|
|
|
||||||
Net income attributable to the period January 1, 2014 through June 22, 2014
|
|
|
|
|
$
|
7,021
|
|
||||
Net income attributable to the period June 23, 2014 through December 31, 2014
|
|
|
|
|
22,613
|
|
|||||
|
|
|
|
|
$
|
29,634
|
|
||||
Production Data:
|
|
|
|
|
|
||||||
Oil (Bbls)
|
1,777,922
|
|
|
1,555,493
|
|
|
856,541
|
|
|||
Natural gas (Mcf)
|
1,490,382
|
|
|
1,128,605
|
|
|
648,808
|
|
|||
Natural gas liquids (Bbls)
|
327,899
|
|
|
238,716
|
|
|
144,074
|
|
|||
Combined volumes (BOE)
|
2,354,218
|
|
|
1,982,310
|
|
|
1,108,750
|
|
|||
Daily combined volumes (BOE/d)
|
6,432
|
|
|
5,431
|
|
|
3,038
|
|
|||
% Oil
|
76
|
%
|
|
78
|
%
|
|
77
|
%
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Oil
|
$
|
40.23
|
|
|
$
|
44.75
|
|
|
$
|
82.98
|
|
Natural Gas
|
$
|
2.08
|
|
|
$
|
2.36
|
|
|
$
|
4.18
|
|
Natural gas liquids
|
$
|
12.84
|
|
|
$
|
10.85
|
|
|
$
|
27.59
|
|
|
2016 vs. 2015
|
|
2015 vs. 2014
|
||||||||||||||||
|
Change in prices
|
Production volumes
(1)
|
Total net dollar effect of change
|
|
Change in prices
|
Production volumes
(1)
|
Total net dollar effect of change
|
||||||||||||
|
(dollars in thousands except change in prices)
|
||||||||||||||||||
Effect of changes in price:
|
|
|
|
|
|
|
|
||||||||||||
Oil
|
$
|
(4.52
|
)
|
1,777,922
|
|
$
|
(8,035
|
)
|
|
$
|
(38.23
|
)
|
1,555,493
|
|
$
|
(59,466
|
)
|
||
Natural gas liquids
|
1.99
|
|
327,899
|
|
653
|
|
|
(16.74
|
)
|
238,716
|
|
(3,996
|
)
|
||||||
Natural gas
|
(0.28
|
)
|
1,490,382
|
|
(417
|
)
|
|
(1.82
|
)
|
1,128,605
|
|
(2,054
|
)
|
||||||
Total income due to change in price
|
|
|
$
|
(7,799
|
)
|
|
|
|
$
|
(65,516
|
)
|
||||||||
|
|
|
|
|
|
|
|
||||||||||||
|
Change in production volumes
(1)
|
Prior period average prices
|
Total net dollar effect of change
|
|
Change in production volumes
(1)
|
Prior period average prices
|
Total net dollar effect of change
|
||||||||||||
|
(dollars in thousands except average prices)
|
||||||||||||||||||
Effect of changes in production volumes:
|
|
|
|
|
|
|
|
||||||||||||
Oil
|
222,429
|
|
$
|
44.75
|
|
$
|
9,955
|
|
|
698,952
|
|
$
|
82.98
|
|
$
|
57,991
|
|
||
Natural gas liquids
|
89,183
|
|
10.85
|
|
968
|
|
|
94,642
|
|
27.59
|
|
2,611
|
|
||||||
Natural gas
|
361,777
|
|
2.36
|
|
854
|
|
|
479,797
|
|
4.18
|
|
2,006
|
|
||||||
Total income due to change in production volumes
|
|
|
11,777
|
|
|
|
|
62,608
|
|
||||||||||
Total change in income
|
|
|
$
|
3,978
|
|
|
|
|
$
|
(2,908
|
)
|
(1)
|
Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Net income (loss)
|
$
|
(10,899
|
)
|
|
$
|
24,419
|
|
|
$
|
29,634
|
|
Interest expense
|
2,455
|
|
|
1,110
|
|
|
487
|
|
|||
Interest expense–related party, net of capitalized interest
|
—
|
|
|
—
|
|
|
10,755
|
|
|||
Non-cash unit-based compensation expense
|
3,815
|
|
|
3,929
|
|
|
2,102
|
|
|||
Depletion
|
29,820
|
|
|
35,436
|
|
|
27,601
|
|
|||
Impairment
|
47,469
|
|
|
3,423
|
|
|
—
|
|
|||
Adjusted EBITDA
|
$
|
72,660
|
|
|
$
|
68,317
|
|
|
$
|
70,579
|
|
Date of Approval
|
|
Quarter
|
|
Amount per Unit
|
|
Distribution Date
|
|
Amount Distributed to Diamondback
|
||||
|
|
|
|
|
|
|
|
(in thousands)
|
||||
February 5, 2015
|
|
Q4 2014
|
|
$
|
0.250
|
|
|
February 27, 2015
|
|
$
|
17,612
|
|
May 1, 2015
|
|
Q1 2015
|
|
$
|
0.189
|
|
|
May 22, 2015
|
|
$
|
13,385
|
|
July 31, 2015
|
|
Q2 2015
|
|
$
|
0.220
|
|
|
August 21, 2015
|
|
$
|
15,499
|
|
October 30, 2015
|
|
Q3 2015
|
|
$
|
0.200
|
|
|
November 20, 2015
|
|
$
|
14,091
|
|
February 12, 2016
|
|
Q4 2015
|
|
$
|
0.228
|
|
|
February 26, 2016
|
|
16,063
|
|
|
May 2, 2016
|
|
Q1 2016
|
|
$
|
0.149
|
|
|
May 23, 2016
|
|
$
|
10,497
|
|
July 21, 2016
|
|
Q2 2016
|
|
$
|
0.189
|
|
|
August 22, 2016
|
|
$
|
13,693
|
|
October 25, 2016
|
|
Q3 2016
|
|
$
|
0.207
|
|
|
November 18, 2016
|
|
$
|
14,997
|
|
February 3, 2017
|
|
Q4 2016
|
|
$
|
0.258
|
|
|
February 24, 2017
|
|
*
|
|
Financial Covenant
|
|
Required Ratio
|
Ratio of total debt to EBITDAX
|
Not greater than 4.0 to 1.0
|
|
Ratio of current assets to liabilities, as defined in the credit agreement
|
Not less than 1.0 to 1.0
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Cash Flow Data:
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
$
|
68,627
|
|
|
$
|
63,832
|
|
|
$
|
51,813
|
|
Net cash used in investing activities
|
(205,721
|
)
|
|
(43,907
|
)
|
|
(96,815
|
)
|
|||
Net cash provided by (used in) financing activities
|
145,768
|
|
|
(34,496
|
)
|
|
59,350
|
|
|||
Net increase (decrease) in cash
|
$
|
8,674
|
|
|
$
|
(14,571
|
)
|
|
$
|
14,348
|
|
|
Payments Due by Period
|
||||||||||||||||||
|
Total
|
|
2017
|
|
2018-2019
|
|
2020-2021
|
|
Thereafter
|
||||||||||
|
(in thousands)
|
||||||||||||||||||
Credit agreement
(1)
|
$
|
120,500
|
|
|
$
|
—
|
|
|
$
|
120,500
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest and commitment fees under our credit agreement
(2)
|
$
|
2,593
|
|
|
$
|
1,031
|
|
|
$
|
1,562
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
123,093
|
|
|
$
|
1,031
|
|
|
$
|
122,062
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Includes the outstanding principal amount under the credit agreement, the table does not include interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged.
|
(2)
|
This table reflects only the minimum amount of interest and commitment fees due, which as of
December 31, 2016
includes a commitment fee equal to
0.375%
per year of the unused portion of the borrowing base of our credit agreement. The table does not include interest expense as we cannot predict the timing of future borrowings and repayments or interest rates to be charged. See Note 5–Debt to our consolidated financial statements and related notes included elsewhere in this Annual Report.
|
Name
|
Age
|
Position With Our General Partner
|
Travis D. Stice
|
55
|
Chief Executive Officer, Director
|
Teresa L. Dick
|
47
|
Chief Financial Officer, Senior Vice President and Assistant Secretary
|
Russell Pantermuehl
|
57
|
Vice President-Reservoir Engineering
|
Randall J. Holder
|
63
|
Vice President, General Counsel and Secretary
|
Steven E. West
|
56
|
Executive Chairman, Director
|
W. Wesley Perry
|
60
|
Director
|
Michael L. Hollis
|
41
|
Director
|
James L. Rubin
|
32
|
Director
|
Rosalind Redfern Grover
|
75
|
Director
|
The Board of Directors of Viper Energy Partners GP LLC
|
Travis D. Stice
|
Steven E. West
|
W. Wesley Perry
|
Michael L. Hollis
|
James L. Rubin
|
Rosalind Redfern Grover
|
Name
|
Fees Earned or Paid in cash (a)
|
Unit Awards (b)
|
Total
|
||||||
Rosalind Redfern Grover (c)(d)
|
$
|
51,000
|
|
$
|
89,876
|
|
$
|
140,876
|
|
W. Duncan Kennedy (c)(d)(e)
|
26,250
|
|
—
|
|
26,250
|
|
|||
W. Wesley Perry (c)(d)
|
76,000
|
|
89,876
|
|
165,876
|
|
|||
James L. Rubin (c)(d)
|
48,500
|
|
89,876
|
|
138,376
|
|
|||
Steven E. West (c)(d)
|
48,500
|
|
89,876
|
|
138,376
|
|
(a)
|
This column reflects the value of a director’s annual retainer, as well as the additional payments for committee membership, committee chairmanship and meeting attendance.
|
(b)
|
The amount in this column represents the aggregate grant date fair value of phantom units granted in the fiscal year calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, “Compensation - Stock Compensation.”
|
(c)
|
Each of Ms. Grover and Messrs. Kennedy, Perry, Rubin and West received a grant of
4,938
phantom units on
August 27, 2015
, of which 1,646 vested and settled on the date of grant and 1,646 vested and settled on June 17, 2016, pursuant to the LTIP, with each unit having a grant date fair value of
$15.48
. Each of Ms. Grover’s and Messrs. Perry’s, Rubin’s and West’s remaining
1,646
phantom units will vest and settle on June 17, 2017. Each phantom unit is the economic equivalent of one of our common units.
|
(d)
|
Each of Ms. Grover and Messrs. Perry, Rubin and West received a grant of 5,424 phantom units on August 24, 2016, of which 1,808 vested and settled on the date of grant, pursuant to the LTIP, with each unit having a grant date fair value of $16.57. Each of Ms. Grover’s and Messrs. Perry’s, Rubin’s and West’s remaining 3,616 phantom units will vest and settle in two equal annual installments beginning on June 17, 2017. Each phantom unit is the economic equivalent of one of our common units.
|
(e)
|
Effective July 4, 2016, Mr. Kennedy resigned from the board of directors of our general partner.
|
•
|
our general partner;
|
•
|
each of our general partner’s directors and executive officers;
|
•
|
each unitholder known by us to beneficially hold
5%
or more of our common units; and
|
•
|
all of our general partner’s directors and executive officers as a group.
|
Name of Beneficial Owner
|
Common Units Beneficially Owned
(1)
|
Percentage of Common Units Beneficially Owned
|
|
Diamondback Energy, Inc.
(2)
|
72,450,000
|
|
74.3%
|
Viper Energy Partners GP LLC
|
—
|
|
—
|
Travis D. Stice
(3)
|
870,834
|
|
*
|
Teresa L. Dick
(4)
|
93,334
|
|
*
|
Russell Pantermuehl
(4)
|
196,666
|
|
*
|
Randall J. Holder
(4)
|
93,334
|
|
*
|
Steven E. West
(5)
|
—
|
|
—
|
W. Wesley Perry
(6)
|
30,766
|
|
*
|
Michael L. Hollis
(7)
|
227,991
|
|
*
|
James L. Rubin
(5)
|
—
|
|
—
|
Rosalind Redfern Grover
(6)
|
5,100
|
|
*
|
All directors and executive officers as a group (9 persons)
|
1,518,025
|
|
1.5%
|
*
|
Less than 1%
|
(1)
|
Beneficial ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, common units subject to options held by that person that are exercisable as of February 6, 2017, or exercisable within 60 days of February 6, 2017, are deemed to be beneficially owned. These common units, however, are not deemed outstanding for the purpose of computing the percentage ownership of each other person. The percentage of common units beneficially owned is based on 97,575,356 common units outstanding as of February 6, 2017. Unless otherwise indicated, all amounts exclude common units issuable upon the exercise of outstanding options and vesting of phantom units that are not exercisable and/or vested as of February 6, 2017 or within 60 days of February 6, 2017. Unless otherwise noted, the address for each beneficial owner listed below is 500 West Texas Avenue, Suite 1200, Midland, Texas 79701.
|
(2)
|
Diamondback Energy, Inc. is a publicly traded company. The directors of Diamondback are Travis D. Stice, Steven E. West, Michael P. Cross, David L. Houston and Mark L. Plaumann.
|
(3)
|
All of these units or options, as applicable, are held by Stice Investments, Ltd., which is managed by Stice Management, LLC, its general partner. Mr. Stice and his spouse hold 100% of the membership interests in Stice Management, LLC, of which Mr. Stice is the manager. Includes 833,334 unit options granted to Mr. Stice, all of which have previously vested. Excludes 416,666 unvested unit options granted to Mr. Stice, which will vest on June 23, 2017. See “Item 11. Executive Compensation - Compensation Discussion and Analysis - Long-Term Incentive Plan” for additional information regarding these options to purchase common units.
|
(4)
|
Includes 166,666, 83,334 and 83,334 unit options held by Mr. Pantermuehl, Ms. Dick and Mr. Holder, respectively, all of which have previously vested. Excludes 83,334, 41,666 and 41,666 unit options granted to Mr. Pantermuehl, Ms. Dick and Mr. Holder, respectively, all of which will vest on June 23, 2017. See “Item 11. Executive Compensation - Compensation Discussion and Analysis - Long-Term Incentive Plan” for additional information regarding these unit options.
|
(5)
|
Excludes 11,766 common units (representing vested phantom units previously granted to such director), 1,646 unvested phantom units that will vest on June 17, 2017 and 3,616 unvested phantom units that will vest in two equal annual installments beginning on June 17, 2017, all of which have been assigned by Messrs. West and Rubin to Wexford under their terms of employment with Wexford.
|
(6)
|
Excludes 1,646 unvested phantom units that will vest on June 17, 2017 and 3,616 unvested phantom units that will vest in two equal annual installments beginning on June 17, 2017.
|
(7)
|
All of the units or options, as applicable, are held by MBH Investments, Ltd., which is managed by MBH Financial, LLC, its general partner. Mr. Hollis, his spouse and the Hollis 2014 Irrevocable Trust hold 100% of the membership interests in MBH Financial, LLC, of which Mr. Hollis is the manager. Includes 166,666 unit options granted to Mr. Hollis, all of which have previously vested. Excludes 83,334 unvested unit options granted to Mr. Hollis, which will vest on June 23, 2017. See “Item 11. Executive Compensation - Compensation Discussion and Analysis - Long-Term Incentive Plan” for additional information regarding these options to purchase common units.
|
|
Shares of Diamondback Common Stock Beneficially Owned
(1)
|
||
Name of Beneficial Owner
|
Amount and Nature of Beneficial Ownership
|
Percentage of
Class |
|
Travis D. Stice
(2)
|
159,390
|
|
*
|
Teresa L. Dick
(3)
|
18,506
|
|
*
|
Russell Pantermuehl
(4)
|
55,499
|
|
*
|
Randall J. Holder
(5)
|
3,948
|
|
*
|
Steven E. West
(6)
|
—
|
|
—
|
W. Wesley Perry
|
—
|
|
—
|
Michael L. Hollis
(7)
|
52,506
|
|
*
|
James L. Rubin
|
—
|
|
—
|
Rosalind Redfern Grover
|
—
|
|
—
|
All directors and executive officers as a group (9 persons)
|
289,849
|
|
*
|
*
|
Less than 1%
|
(1)
|
Beneficial ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, shares of common stock subject to options held by that person that are exercisable as of February 6, 2017, or exercisable within 60 days of February 6, 2017, are deemed to be beneficially owned. These shares, however, are not deemed outstanding for the purpose of computing the percentage ownership of each other person. The percentage of shares beneficially owned is based on 90,143,934 shares of common stock outstanding as of February 6, 2017. Unless otherwise indicated, all amounts exclude shares issuable upon the exercise of outstanding options and vesting of restricted stock units that are not exercisable and/or vested as of February 6, 2017 or within 60 days of February 6, 2017.
|
(2)
|
All of these shares are held by Stice Investments, Ltd., which is managed by Stice Management, LLC, its general partner. Mr. Stice and his spouse hold 100% of the membership interests in Stice Management, LLC, of which Mr. Stice is the manager. Excludes 30,056 restricted stock units, which will vest on January 2, 2018. Also excludes (i) 71,666 performance-based restricted stock units awarded to Mr. Stice on February 5, 2015, which are expected to vest in February of 2017 (representing 200% vesting of the originally reported amount) upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ended on December 31, 2016 by Diamondback’s compensation committee, and (ii) 45,084 performance-based restricted stock units awarded to Mr. Stice on January 19, 2016, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2018. Also excludes 90,169 performance-based restricted stock units awarded to Mr. Stice on January 19, 2016, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ending on December 31, 2017.
|
(3)
|
Excludes 2,004 restricted stock units, which will vest on January 2, 2018. Also excludes (i) 15,000 performance-based restricted stock units awarded to Ms. Dick on February 5, 2015, which are expected to vest in February of 2017 (representing 200% vesting of the originally reported amount) upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ended on December 31, 2016 by Diamondback’s compensation committee, and (ii) 3,006 performance-based restricted stock units awarded to Ms. Dick on January 19, 2016, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2018. Also excludes 6,011 performance-based restricted stock units awarded to Ms. Dick on January 19, 2016, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ending on December 31, 2017.
|
(4)
|
Excludes 8,015 restricted stock units, which will vest on January 2, 2018. Also excludes (i) 20,000 performance-based restricted stock units awarded to Mr. Pantermuehl on February 5, 2015, which are expected to vest in February of 2017 (representing 200% vesting of the originally reported amount) upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ended on December 31, 2016 by Diamondback’s compensation committee, and (ii) 12,022 performance-based restricted stock units awarded to Mr. Pantermuehl on January 19, 2016, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2018. Also excludes 24,045 performance-based restricted stock units awarded to Mr. Pantermuehl on January 19, 2016, which are
|
(5)
|
Excludes 2,004 restricted stock units, which will vest on January 2, 2018. Also excludes 11,666 performance-based restricted stock units awarded to Mr. Holder on February 5, 2015, which are expected to vest in February of 2017 (representing 200% vesting of the originally reported amount) upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ended on December 31, 2016 by Diamondback’s compensation committee, and (ii) 3,006 performance-based restricted stock units awarded to Mr. Holder on January 19, 2016, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2018. Also excludes 6,011 performance-based restricted stock units awarded to Mr. Holder on January 19, 2016, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ending on December 31, 2017.
|
(6)
|
Excludes 10,973 shares of Diamondback common stock (representing vested restricted stock units previously granted to Mr. West), 526 unvested restricted stock units that will vest on July 1, 2017 and 906 unvested restricted stock units that will vest in two equal annual installments beginning on July 1, 2017, all of which were assigned by Mr. West to Wexford under the terms of Mr. West’s employment with Wexford.
|
(7)
|
All of these shares are held by MBH Investments, Ltd., which is managed by MBH Financial, LLC, its general partner. Mr. Hollis, his spouse and the Hollis 2014 Irrevocable Trust hold 100% of the membership interests in MBH Financial, LLC, of which Mr. Hollis is the manager. Excludes 10,019 restricted stock units, which will vest on January 2, 2018. Also excludes 20,000 performance-based restricted stock units awarded to Mr. Hollis on February 5, 2015, which are expected to vest in February of 2017 (representing 200% vesting of the originally reported amount) upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance periods ending on December 31, 2016 by Diamondback’s compensation committee, and (ii) 15,028 performance-based restricted stock units awarded to Mr. Hollis on January 19, 2016, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2018. Also excludes 30,056 performance-based restricted stock units awarded to Mr. Hollis on January 19, 2016, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ending on December 31, 2017.
|
Plan Category
|
Number of securities to be issued upon exercise of outstanding options, warrants and rights
|
Weighted-average exercise price of outstanding options, warrants and rights
(2)
|
Number of securities remaining available for future issuance under equity compensation plans
|
||||
Equity compensation plans not approved by security holders
(1)
|
|
|
|
||||
Long Term Incentive Plan
|
2,445,314
|
|
$
|
25.98
|
|
6,674,336
|
|
(1)
|
Our general partner adopted the LTIP in connection with the IPO in June 2014.
|
(2)
|
Reflects the weighted average exercise price for each of the 2,416,666 outstanding unit options.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Audit fees
(1)
|
$
|
116
|
|
|
$
|
97
|
|
|
$
|
193
|
|
Audit-related fees
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|||
Tax fees
(3)
|
—
|
|
|
—
|
|
|
—
|
|
|||
All other fees
(4)
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total
|
$
|
116
|
|
|
$
|
97
|
|
|
$
|
193
|
|
(1)
|
Audit fees represent amounts billed for each of the periods presented for professional services rendered in connection with those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters.
|
(2)
|
Audit-related fees represent amounts billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews.
|
(3)
|
Tax fees represent amounts billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice, and tax planning.
|
(4)
|
All other fees represent amounts billed in each of the years presented for services not classifiable under the other categories listed in the table above.
|
(a)
|
Documents included in this report:
|
|
|
1. Financial Statements
|
|
|
||
|
||
|
||
|
||
|
||
|
||
|
|
|
|
2. Financial Statement Schedules
|
|
|
Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Partnership’s consolidated financial statements and related notes.
|
|
|
|
|
|
3. Exhibits
|
|
|
The Exhibit Index beginning on page E–1 of this report is incorporated herein by reference.
|
|
|
|
VIPER ENERGY PARTNERS LP
|
|
Date:
|
February 15, 2017
|
|
|
|
|
By:
|
VIPER ENERGY PARTNERS GP LLC
|
|
|
|
its general partner
|
|
|
|
|
|
|
By:
|
/s/ Travis D. Stice
|
|
|
Name:
|
Travis D. Stice
|
|
|
Title:
|
Chief Executive Officer
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Travis D. Stice
|
|
Chief Executive Officer and Director
|
|
February 15, 2017
|
Travis D. Stice
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ Teresa L. Dick
|
|
Chief Financial Officer
|
|
February 15, 2017
|
Teresa L. Dick
|
|
(Principal Financial and Accounting Officer)
|
|
|
|
|
|
|
|
/s/ Steven E. West
|
|
Director
|
|
February 15, 2017
|
Steven E. West
|
|
|
|
|
|
|
|
|
|
/s/ W. Wesley Perry
|
|
Director
|
|
February 15, 2017
|
W. Wesley Perry
|
|
|
|
|
|
|
|
|
|
/s/ Michael L. Hollis
|
|
Director
|
|
February 15, 2017
|
Michael L. Hollis
|
|
|
|
|
|
|
|
|
|
/s/ James L. Rubin
|
|
Director
|
|
February 15, 2017
|
James L. Rubin
|
|
|
|
|
|
|
|
|
|
/s/ Rosalind Redfern Grover
|
|
Director
|
|
February 15, 2017
|
Rosalind Redfern Grover
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
|
|
|
||||
|
(In thousands, except unit amounts)
|
||||||
Assets
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
9,213
|
|
|
$
|
539
|
|
Restricted cash
|
500
|
|
|
500
|
|
||
Royalty income receivable
|
10,043
|
|
|
7,441
|
|
||
Royalty income receivable—related party
|
3,470
|
|
|
1,928
|
|
||
Other current assets
|
187
|
|
|
476
|
|
||
Total current assets
|
23,413
|
|
|
10,884
|
|
||
Property and equipment:
|
|
|
|
||||
Oil and natural gas interests, full cost method of accounting ($252,232 and $85,329 excluded from depletion at December 31, 2016 and 2015, respectively)
|
760,818
|
|
|
554,992
|
|
||
Accumulated depletion and impairment
|
(148,948
|
)
|
|
(71,659
|
)
|
||
Oil and natural gas interests, net
|
611,870
|
|
|
483,333
|
|
||
Other assets
|
35,266
|
|
|
35,514
|
|
||
Total assets
|
$
|
670,549
|
|
|
$
|
529,731
|
|
Liabilities and Unitholders’ Equity
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
1,780
|
|
|
$
|
1
|
|
Accounts payable—related party
|
—
|
|
|
4
|
|
||
Other accrued liabilities
|
371
|
|
|
82
|
|
||
Total current liabilities
|
2,151
|
|
|
87
|
|
||
Long-term debt
|
120,500
|
|
|
34,500
|
|
||
Total liabilities
|
122,651
|
|
|
34,587
|
|
||
Commitments and contingencies (Note 10)
|
|
|
|
||||
Unitholders’ equity:
|
|
|
|
||||
Common units (87,800,356 units issued and outstanding and 79,726,006 units issued and outstanding as of December 31, 2016 and 2015, respectively)
|
547,898
|
|
|
495,144
|
|
||
Total unitholders’ equity
|
547,898
|
|
|
495,144
|
|
||
Total liabilities and unitholders’ equity
|
$
|
670,549
|
|
|
$
|
529,731
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(In thousands, except per unit amounts)
|
||||||||||
Operating income:
|
|
|
|
|
|
||||||
Royalty income
|
$
|
78,837
|
|
|
$
|
74,859
|
|
|
$
|
77,767
|
|
Lease bonus
|
309
|
|
|
—
|
|
|
—
|
|
|||
Total operating income
|
79,146
|
|
|
74,859
|
|
|
77,767
|
|
|||
Costs and expenses:
|
|
|
|
|
|
||||||
Production and ad valorem taxes
|
5,544
|
|
|
5,531
|
|
|
5,377
|
|
|||
Gathering and transportation
|
415
|
|
|
259
|
|
|
—
|
|
|||
Depletion
|
29,820
|
|
|
35,436
|
|
|
27,601
|
|
|||
Impairment
|
47,469
|
|
|
3,423
|
|
|
—
|
|
|||
General and administrative expenses
|
5,209
|
|
|
5,835
|
|
|
4,372
|
|
|||
Total costs and expenses
|
88,457
|
|
|
50,484
|
|
|
37,350
|
|
|||
Income (loss) from operations
|
(9,311
|
)
|
|
24,375
|
|
|
40,417
|
|
|||
Other income (expense):
|
|
|
|
|
|
||||||
Interest expense
|
(2,455
|
)
|
|
(1,110
|
)
|
|
(487
|
)
|
|||
Interest expense—related party, net of capitalized interest
|
—
|
|
|
—
|
|
|
(10,755
|
)
|
|||
Other income
|
867
|
|
|
1,154
|
|
|
459
|
|
|||
Total other income (expense), net
|
(1,588
|
)
|
|
44
|
|
|
(10,783
|
)
|
|||
Net income (loss)
|
$
|
(10,899
|
)
|
|
$
|
24,419
|
|
|
$
|
29,634
|
|
Allocation of net income:
|
|
|
|
|
|
||||||
Net income attributable to the period January 1, 2014 through June 22, 2014
|
|
|
|
|
$
|
7,021
|
|
||||
Net income attributable to the period June 23, 2014 through December 31, 2014
|
|
|
|
|
22,613
|
|
|||||
|
|
|
|
|
$
|
29,634
|
|
||||
Net income attributable to common limited partners per unit:
|
|
|
|
|
|
||||||
Basic and Diluted*
|
$
|
(0.13
|
)
|
|
$
|
0.31
|
|
|
$
|
0.29
|
|
Weighted average number of limited partner units outstanding:
|
|
|
|
|
|
||||||
Basic*
|
83,081
|
|
79,717
|
|
78,090
|
||||||
Diluted*
|
83,081
|
|
79,727
|
|
78,102
|
|
Limited Partners
|
|
|
|
|
|||||||||
|
Common Units
|
|
Amount
|
|
Predecessor Members' Equity
|
|
Total
|
|||||||
|
|
|
(In thousands)
|
|||||||||||
Balance at December 31, 2013*
|
|
|
$
|
—
|
|
|
$
|
2,988
|
|
|
$
|
2,988
|
|
|
Net income attributable to the period January 1, 2014 through June 22, 2014
|
|
|
—
|
|
|
7,021
|
|
|
7,021
|
|
||||
Contribution of note payable to equity
|
|
|
—
|
|
|
437,115
|
|
|
437,115
|
|
||||
Exchange of Predecessor interests for units (Note 1)
|
70,450
|
|
|
447,124
|
|
|
(447,124
|
)
|
|
—
|
|
|||
Net proceeds from the issuance of common units
|
9,250
|
|
|
232,198
|
|
|
—
|
|
|
232,198
|
|
|||
Distribution of net proceeds to Diamondback (Note 1)
|
|
|
(148,760
|
)
|
|
—
|
|
|
(148,760
|
)
|
||||
Unit-based compensation
|
9
|
|
|
2,102
|
|
|
—
|
|
|
2,102
|
|
|||
Distribution to public
|
|
|
(2,314
|
)
|
|
—
|
|
|
(2,314
|
)
|
||||
Distribution to Diamondback
|
|
|
(17,612
|
)
|
|
—
|
|
|
(17,612
|
)
|
||||
Net income attributable to the period June 23, 2014 through December 31, 2014
|
|
|
22,613
|
|
|
—
|
|
|
22,613
|
|
||||
Balance at December 31, 2014
|
79,709
|
|
|
$
|
535,351
|
|
|
$
|
—
|
|
|
$
|
535,351
|
|
Unit-based compensation
|
17
|
|
|
3,929
|
|
|
—
|
|
|
3,929
|
|
|||
Distributions to public
|
|
|
(7,968
|
)
|
|
—
|
|
|
(7,968
|
)
|
||||
Distributions to Diamondback
|
|
|
(60,587
|
)
|
|
—
|
|
|
(60,587
|
)
|
||||
Net income
|
|
|
24,419
|
|
|
—
|
|
|
24,419
|
|
||||
Balance at December 31, 2015
|
79,726
|
|
|
$
|
495,144
|
|
|
$
|
—
|
|
|
$
|
495,144
|
|
Net proceeds from the issuance of common units - Public
|
6,050
|
|
|
93,462
|
|
|
—
|
|
|
93,462
|
|
|||
Net proceeds from the issuance of common units - Diamondback
|
2,000
|
|
|
31,200
|
|
|
—
|
|
|
31,200
|
|
|||
Unit-based compensation
|
24
|
|
|
3,815
|
|
|
—
|
|
|
3,815
|
|
|||
Distributions to public
|
|
|
(9,574
|
)
|
|
—
|
|
|
(9,574
|
)
|
||||
Distributions to Diamondback
|
|
|
(55,250
|
)
|
|
—
|
|
|
(55,250
|
)
|
||||
Net loss
|
|
|
(10,899
|
)
|
|
—
|
|
|
(10,899
|
)
|
||||
Balance at December 31, 2016
|
87,800
|
|
|
$
|
547,898
|
|
|
$
|
—
|
|
|
$
|
547,898
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(In thousands)
|
||||||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
(10,899
|
)
|
|
$
|
24,419
|
|
|
$
|
29,634
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depletion
|
29,820
|
|
|
35,436
|
|
|
27,601
|
|
|||
Impairment
|
47,469
|
|
|
3,423
|
|
|
—
|
|
|||
Amortization of debt issuance costs
|
401
|
|
|
314
|
|
|
112
|
|
|||
Non-cash unit-based compensation
|
3,815
|
|
|
3,929
|
|
|
2,102
|
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
||||||
Restricted cash
|
—
|
|
|
—
|
|
|
(500
|
)
|
|||
Royalty income receivable
|
(4,144
|
)
|
|
(1,130
|
)
|
|
1,187
|
|
|||
Accounts payable—related party
|
(4
|
)
|
|
4
|
|
|
(9,779
|
)
|
|||
Accounts payable and other accrued liabilities
|
1,945
|
|
|
(1,968
|
)
|
|
1,709
|
|
|||
Prepaid expenses and other current assets
|
224
|
|
|
(595
|
)
|
|
(253
|
)
|
|||
Net cash provided by operating activities
|
68,627
|
|
|
63,832
|
|
|
51,813
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Additions to oil and natural gas interests
|
—
|
|
|
—
|
|
|
(5,276
|
)
|
|||
Acquisition of royalty interests
|
(205,721
|
)
|
|
(43,907
|
)
|
|
(57,689
|
)
|
|||
Cost method investment
|
—
|
|
|
—
|
|
|
(33,850
|
)
|
|||
Net cash used in investing activities
|
(205,721
|
)
|
|
(43,907
|
)
|
|
(96,815
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from borrowings under credit facility
|
164,000
|
|
|
34,500
|
|
|
78,000
|
|
|||
Repayment on credit facility
|
(78,000
|
)
|
|
—
|
|
|
(78,000
|
)
|
|||
Principal payment on subordinated note
|
—
|
|
|
—
|
|
|
(2,885
|
)
|
|||
Debt issuance costs
|
(442
|
)
|
|
(441
|
)
|
|
(1,277
|
)
|
|||
Proceeds from public offerings
|
125,580
|
|
|
—
|
|
|
234,546
|
|
|||
Public offering costs
|
(546
|
)
|
|
—
|
|
|
(2,348
|
)
|
|||
Distribution of net proceeds from public offerings to Diamondback (Note 1)
|
—
|
|
|
—
|
|
|
(148,760
|
)
|
|||
Distributions to partners
|
(64,824
|
)
|
|
(68,555
|
)
|
|
(19,926
|
)
|
|||
Net cash provided by (used in) financing activities
|
145,768
|
|
|
(34,496
|
)
|
|
59,350
|
|
|||
Net increase (decrease) in cash
|
8,674
|
|
|
(14,571
|
)
|
|
14,348
|
|
|||
Cash and cash equivalents at beginning of period
|
539
|
|
|
15,110
|
|
|
762
|
|
|||
Cash and cash equivalents at end of period
|
$
|
9,213
|
|
|
$
|
539
|
|
|
$
|
15,110
|
|
Supplemental disclosure of cash flow information:
|
|
|
|
|
|
||||||
Interest paid, net of capitalized interest
|
$
|
1,953
|
|
|
$
|
745
|
|
|
$
|
16,983
|
|
Supplemental disclosure of non—cash transactions:
|
|
|
|
|
|
||||||
Note payable converted to equity
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
437,115
|
|
Capitalized interest
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,275
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Oil and natural gas interests:
|
|
|
|
||||
Subject to depletion
|
$
|
508,586
|
|
|
$
|
469,663
|
|
Not subject to depletion
|
252,232
|
|
|
85,329
|
|
||
Gross oil and natural gas interests
|
760,818
|
|
|
554,992
|
|
||
Accumulated depletion and impairment
|
(148,948
|
)
|
|
(71,659
|
)
|
||
Oil and natural gas interests, net
|
$
|
611,870
|
|
|
$
|
483,333
|
|
|
|
|
|
||||
Balance of acquisition costs not subject to depletion
|
|
|
|
||||
Incurred in 2016
|
$
|
169,528
|
|
|
|
||
Incurred in 2015
|
$
|
37,112
|
|
|
|
||
Incurred in 2014
|
$
|
45,592
|
|
|
|
Financial Covenant
|
|
Required Ratio
|
Ratio of total debt to EBITDAX
|
Not greater than 4.0 to 1.0
|
|
Ratio of current assets to liabilities, as defined in the credit agreement
|
Not less than 1.0 to 1.0
|
|
2014
|
||
Grant-date fair value
|
$
|
4.24
|
|
Expected volatility
|
36.0
|
%
|
|
Expected dividend yield
|
5.9
|
%
|
|
Expected term (in years)
|
3.0
|
|
|
Risk-free rate
|
0.99
|
%
|
|
|
|
Weighted Average
|
|
|
|||||||
|
Unit
Options |
|
Exercise
Price |
|
Remaining
Term |
|
Intrinsic
Value |
|||||
|
|
|
|
|
(in years)
|
|
(in thousands)
|
|||||
Outstanding at December 31, 2015
|
2,500,000
|
|
|
$
|
26.00
|
|
|
|
|
|
||
Granted
|
7,600
|
|
|
$
|
18.49
|
|
|
|
|
|
||
Expired/Forfeited
|
(83,334
|
)
|
|
$
|
26.00
|
|
|
|
|
|
||
Outstanding at December 31, 2016
|
2,424,266
|
|
|
$
|
—
|
|
|
0.47
|
|
$
|
—
|
|
Vested and Expected to Vest at December 31, 2016
|
2,424,266
|
|
|
$
|
—
|
|
|
0.47
|
|
$
|
—
|
|
Exercisable at December 31, 2016
|
—
|
|
|
$
|
—
|
|
|
0.00
|
|
$
|
—
|
|
|
Phantom
Units |
|
Weighted Average
Grant-Date Fair Value |
|||
Unvested at December 31, 2015
|
25,348
|
|
|
$
|
16.89
|
|
Granted
|
21,696
|
|
|
$
|
16.57
|
|
Vested
|
(24,350
|
)
|
|
$
|
17.27
|
|
Forfeited
|
(1,646
|
)
|
|
$
|
15.48
|
|
Unvested at December 31, 2016
|
21,048
|
|
|
$
|
16.23
|
|
|
Common Units
|
|
Balance at December 31, 2015
|
79,726,006
|
|
Common units issued in August 2016 public offering
|
8,050,000
|
|
Common units vested and issued under the LTIP
|
24,350
|
|
Balance at December 31, 2016
|
87,800,356
|
|
Date of Approval
|
|
Quarter
|
|
Amount per Unit
|
|
Distribution Date
|
|
Amount Distributed to Diamondback
|
||||
|
|
|
|
|
|
|
|
(in thousands)
|
||||
February 5, 2015
|
|
Q4 2014
|
|
$
|
0.250
|
|
|
February 27, 2015
|
|
$
|
17,612
|
|
May 1, 2015
|
|
Q1 2015
|
|
$
|
0.189
|
|
|
May 22, 2015
|
|
$
|
13,385
|
|
July 31, 2015
|
|
Q2 2015
|
|
$
|
0.220
|
|
|
August 21, 2015
|
|
$
|
15,499
|
|
October 30, 2015
|
|
Q3 2015
|
|
$
|
0.200
|
|
|
November 20, 2015
|
|
$
|
14,091
|
|
February 12, 2016
|
|
Q4 2015
|
|
$
|
0.228
|
|
|
February 26, 2016
|
|
$
|
16,063
|
|
May 2, 2016
|
|
Q1 2016
|
|
$
|
0.149
|
|
|
May 23, 2016
|
|
$
|
10,497
|
|
July 21, 2016
|
|
Q2 2016
|
|
$
|
0.189
|
|
|
August 22, 2016
|
|
$
|
13,693
|
|
October 25, 2016
|
|
Q3 2016
|
|
$
|
0.207
|
|
|
November 18, 2016
|
|
$
|
14,997
|
|
|
Year Ended December 31,
|
|
June 23 through
December 31, 2014 |
||||||||
|
2016
|
|
2015
|
|
|||||||
|
(in thousands, except per unit amounts)
|
||||||||||
Net income (loss) attributable to the period
|
$
|
(10,899
|
)
|
|
$
|
24,419
|
|
|
$
|
22,613
|
|
Net income per common unit, basic
|
$
|
(0.13
|
)
|
|
$
|
0.31
|
|
|
$
|
0.29
|
|
Net income per common unit, diluted
|
$
|
(0.13
|
)
|
|
$
|
0.31
|
|
|
$
|
0.29
|
|
Weighted-average common units outstanding, basic
|
83,081
|
|
|
79,717
|
|
|
78,090
|
|
|||
Weighted-average common units outstanding, diluted
|
83,081
|
|
|
79,727
|
|
|
78,102
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(In thousands)
|
||||||
Oil and natural gas interests:
|
|
|
|
||||
Proved
|
$
|
508,586
|
|
|
$
|
469,663
|
|
Unproved
|
252,232
|
|
|
85,329
|
|
||
Total oil and natural gas interests
|
760,818
|
|
|
554,992
|
|
||
Accumulated depletion and impairment
|
(148,948
|
)
|
|
(71,659
|
)
|
||
Net oil and natural gas interests capitalized
|
$
|
611,870
|
|
|
$
|
483,333
|
|
|
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(In thousands)
|
||||||||||
Acquisition costs
|
|
|
|
|
|
||||||
Proved properties
|
$
|
31,441
|
|
|
$
|
4,121
|
|
|
$
|
10,879
|
|
Unproved properties
|
174,385
|
|
|
39,786
|
|
|
46,810
|
|
|||
Total
|
$
|
205,826
|
|
|
$
|
43,907
|
|
|
$
|
57,689
|
|
|
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(In thousands)
|
||||||||||
Royalty income
|
$
|
78,837
|
|
|
$
|
74,859
|
|
|
$
|
77,767
|
|
Production and ad valorem taxes
|
(5,544
|
)
|
|
(5,531
|
)
|
|
(5,377
|
)
|
|||
Gathering and transportation
|
(415
|
)
|
|
(259
|
)
|
|
—
|
|
|||
Depletion
|
(29,820
|
)
|
|
(35,436
|
)
|
|
(27,601
|
)
|
|||
Impairment
|
(47,469
|
)
|
|
(3,423
|
)
|
|
—
|
|
|||
Results of operations from oil, natural gas and natural gas liquids
|
$
|
(4,411
|
)
|
|
$
|
30,210
|
|
|
$
|
44,789
|
|
|
Oil
(Bbls) |
|
Natural Gas Liquids
(Bbls) |
|
Natural Gas
(Mcf) |
|||
Proved Developed and Undeveloped Reserves:
|
|
|
|
|
|
|||
As of December 31, 2013
|
7,218,080
|
|
|
1,175,123
|
|
|
11,261,585
|
|
Purchase of reserves in place
|
225,217
|
|
|
—
|
|
|
346,123
|
|
Extensions and discoveries
|
6,937,134
|
|
|
1,370,291
|
|
|
9,831,241
|
|
Revisions of previous estimates
|
(693,596
|
)
|
|
112,368
|
|
|
(1,795,981
|
)
|
Production
|
(856,541
|
)
|
|
(144,074
|
)
|
|
(648,808
|
)
|
As of December 31, 2014
|
12,830,294
|
|
|
2,513,708
|
|
|
18,994,160
|
|
Purchase of reserves in place
|
107,072
|
|
|
3,640
|
|
|
430,733
|
|
Extensions and discoveries
|
8,449,586
|
|
|
2,012,599
|
|
|
9,476,316
|
|
Revisions of previous estimates
|
(1,454,037
|
)
|
|
(375,275
|
)
|
|
(3,464,719
|
)
|
Production
|
(1,555,493
|
)
|
|
(238,716
|
)
|
|
(1,128,605
|
)
|
As of December 31, 2015
|
18,377,422
|
|
|
3,915,956
|
|
|
24,307,885
|
|
Purchase of reserves in place
|
1,137,783
|
|
|
436,846
|
|
|
2,315,051
|
|
Extensions and discoveries
|
5,647,430
|
|
|
1,477,074
|
|
|
7,181,625
|
|
Revisions of previous estimates
|
(2,040,713
|
)
|
|
74,023
|
|
|
(5,223,179
|
)
|
Production
|
(1,777,922
|
)
|
|
(327,899
|
)
|
|
(1,490,382
|
)
|
As of December 31, 2016
|
21,344,000
|
|
|
5,576,000
|
|
|
27,091,000
|
|
|
|
|
|
|
|
|||
Proved Developed Reserves:
|
|
|
|
|
|
|||
December 31, 2014
|
6,951,892
|
|
|
1,470,966
|
|
|
10,377,401
|
|
December 31, 2015
|
9,700,000
|
|
|
2,204,951
|
|
|
13,739,050
|
|
December 31, 2016
|
12,332,000
|
|
|
3,247,000
|
|
|
15,933,000
|
|
|
|
|
|
|
|
|||
Proved Undeveloped Reserves:
|
|
|
|
|
|
|||
December 31, 2014
|
5,878,402
|
|
|
1,042,742
|
|
|
8,616,759
|
|
December 31, 2015
|
8,677,422
|
|
|
1,711,005
|
|
|
10,568,835
|
|
December 31, 2016
|
9,012,000
|
|
|
2,329,000
|
|
|
11,158,000
|
|
|
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(In thousands)
|
||||||||||
Future cash inflows
|
$
|
948,090
|
|
|
$
|
912,276
|
|
|
$
|
1,287,730
|
|
Future production taxes
|
(69,109
|
)
|
|
(61,777
|
)
|
|
(88,559
|
)
|
|||
Future state margin tax expenses
|
(4,615
|
)
|
|
(4,789
|
)
|
|
(9,014
|
)
|
|||
Future net cash flows
|
874,366
|
|
|
845,710
|
|
|
1,190,157
|
|
|||
10% discount to reflect timing of cash flows
|
(461,785
|
)
|
|
(449,947
|
)
|
|
(636,921
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
412,581
|
|
|
$
|
395,763
|
|
|
$
|
553,236
|
|
|
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
Unweighted Arithmetic Average
|
||||||||||
|
First-Day-of-the-Month Prices
|
||||||||||
Oil (per Bbl)
|
$
|
39.64
|
|
|
$
|
45.03
|
|
|
$
|
87.33
|
|
Natural gas (per Mcf)
|
$
|
1.36
|
|
|
$
|
1.64
|
|
|
$
|
5.12
|
|
Natural gas liquids (per Bbl)
|
$
|
11.69
|
|
|
$
|
11.41
|
|
|
$
|
27.87
|
|
|
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(In thousands)
|
||||||||||
Standardized measure of discounted future net cash flows at the beginning of the period
|
$
|
395,763
|
|
|
$
|
553,236
|
|
|
$
|
327,246
|
|
Purchase of minerals in place
|
23,651
|
|
|
2,963
|
|
|
10,879
|
|
|||
Sales of oil and natural gas, net of production costs
|
(74,628
|
)
|
|
(69,328
|
)
|
|
(72,390
|
)
|
|||
Extensions and discoveries
|
104,451
|
|
|
181,330
|
|
|
287,837
|
|
|||
Net changes in prices and production costs
|
(42,155
|
)
|
|
(269,154
|
)
|
|
(17,266
|
)
|
|||
Revisions of previous quantity estimates
|
(42,883
|
)
|
|
(71,399
|
)
|
|
(28,270
|
)
|
|||
Net changes in state margin taxes
|
51
|
|
|
(1,884
|
)
|
|
(1,650
|
)
|
|||
Accretion of discount
|
39,800
|
|
|
54,911
|
|
|
33,450
|
|
|||
Net changes in timing of production and other
|
8,531
|
|
|
15,088
|
|
|
13,400
|
|
|||
Standardized measure of discounted future net cash flows at the end of the period
|
$
|
412,581
|
|
|
$
|
395,763
|
|
|
$
|
553,236
|
|
|
2016
|
||||||||||||||
|
First
Quarter |
|
Second
Quarter |
|
Third
Quarter |
|
Fourth
Quarter |
||||||||
|
(In thousands, except per unit amounts)
|
||||||||||||||
Royalty income
|
$
|
14,086
|
|
|
$
|
16,836
|
|
|
$
|
19,992
|
|
|
$
|
27,923
|
|
Income (loss) from operations
|
(23,104
|
)
|
|
(13,711
|
)
|
|
10,594
|
|
|
16,910
|
|
||||
Net income (loss)
|
(23,335
|
)
|
|
(14,020
|
)
|
|
10,202
|
|
|
16,254
|
|
||||
Net income attributable to common limited partners per unit:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(0.29
|
)
|
|
$
|
(0.18
|
)
|
|
$
|
0.12
|
|
|
$
|
0.20
|
|
Diluted
|
$
|
(0.29
|
)
|
|
$
|
(0.18
|
)
|
|
$
|
0.12
|
|
|
$
|
0.20
|
|
|
2015
|
||||||||||||||
|
First
Quarter |
|
Second
Quarter |
|
Third
Quarter |
|
Fourth
Quarter |
||||||||
|
(In thousands, except per unit amounts)
|
||||||||||||||
Royalty income
|
$
|
16,545
|
|
|
$
|
19,619
|
|
|
$
|
18,777
|
|
|
$
|
19,918
|
|
Income from operations
|
4,764
|
|
|
7,946
|
|
|
6,545
|
|
|
5,120
|
|
||||
Net income
|
5,082
|
|
|
8,045
|
|
|
6,355
|
|
|
4,937
|
|
||||
Net income attributable to common limited partners per unit:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.06
|
|
|
$
|
0.10
|
|
|
$
|
0.08
|
|
|
$
|
0.06
|
|
Diluted
|
$
|
0.06
|
|
|
$
|
0.10
|
|
|
$
|
0.08
|
|
|
$
|
0.06
|
|
Exhibit Number
|
|
Description
|
3.1
|
|
Certificate of Limited Partnership of Viper Energy Partners LP (incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-195769) filed on May 7, 2014).
|
3.2
|
|
First Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
|
4.1
|
|
Registration Rights Agreement, dated June 23, 2014, by and among Viper Energy Partners LP and Diamondback Energy, Inc. (incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
|
10.1
|
|
Senior Secured Revolving Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, as borrower, Wells Fargo Bank, National Association, as the administrative agent, sole book runner and lead arranger, and certain lenders from time to time party thereto. (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on July 14, 2014).
|
10.2
|
|
First Amendment, dated as of August 15, 2014, to Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, as borrower, the guarantors party thereto, Wells Fargo, National Association, as administrative agent, and certain lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Form 10-Q (File No. 001-36505) filed on August 6, 2015).
|
10.3
|
|
Second Amendment, dated as of May 22, 2015, to Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, as borrower, the guarantors party thereto, Wells Fargo, National Association, as administrative agent, and certain lenders party thereto (incorporated by reference to Exhibit 10.2 of the Partnership’s Form 10-Q (File No. 001-36505) filed on August 6, 2015).
|
10.4
|
|
Third Amendment, dated as of June 21, 2016, to the Credit Agreement, dated as of July 8, 2014, by and among Viper Energy Partners LP, as borrower, Viper Energy Partners LLC, as guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 27, 2016).
|
10.5
|
|
Fourth Amendment, dated as of October 28, 2016, to the Credit Agreement, dated as of July 8, 2014, by and among Viper Energy Partners LP, as borrower, Viper Energy Partners LLC, as guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on November 3, 2016).
|
10.6
|
|
Contribution Agreement, dated June 17, 2014, by and among Viper Energy Partners LLC, Viper Energy Partners GP LLC, Viper Energy Partners LP and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
|
10.7+
|
|
Viper Energy Partners LP Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
|
10.8
|
|
Advisory Services Agreement, dated June 23, 2014, by and among Viper Energy Partners LP, Viper Energy Partners GP LLC and Wexford Capital LP (incorporated by reference to Exhibit 10.3 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
|
10.9
|
|
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.4 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
|
10.1
|
|
Tax Sharing Agreement, dated June 23, 2014, by and between Viper Energy Partners LP and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.5 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
|
10.11+
|
|
Form of Unit Option Agreement (incorporated by reference to Exhibit 10.6 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
|
10.12+
|
|
Form of Phantom Unit Agreement (incorporated by reference to Exhibit 10.2 of the Partnership’s Quarterly Report on Form 10-Q (File No. 001-36505) filed on November 6, 2014).
|
21.1*
|
|
List of Subsidiaries of Viper Energy Partners LP.
|
23.1*
|
|
Consent of Grant Thornton LLP.
|
23.2*
|
|
Consent of Ryder Scott Company, LP.
|
31.1*
|
|
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
|
31.2*
|
|
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
|
Exhibit Number
|
|
Description
|
32.1++
|
|
Certification of Chief Executive Officer and Chief Financial Officer pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
|
99.1*
|
|
Reserve Report of Ryder Scott Company, L.P.
|
101.INS*
|
|
XBRL Instance Document.
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document.
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase.
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
101.LAB*
|
|
XBRL Taxonomy Extension Labels Linkbase Document.
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
*
|
Filed herewith.
|
+
|
Management contract, compensatory plan or arrangement.
|
++
|
The certifications attached as Exhibit 32.1 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
|
1 Year Viper Energy Chart |
1 Month Viper Energy Chart |
It looks like you are not logged in. Click the button below to log in and keep track of your recent history.
Support: +44 (0) 203 8794 460 | support@advfn.com
By accessing the services available at ADVFN you are agreeing to be bound by ADVFN's Terms & Conditions